The present disclosure is related to drilling boreholes and, more particularly, to measuring the rotational speed of a drill bit during operation.
In the oil and gas industry, drilling fluid is often used to hydraulically power downhole drilling motors or “mud motors” in order to rotate a drill bit. One type of mud motor is a turbodrill, which includes a turbine that has multiple rotor/stator stages configured to allow the circulating drilling fluid to pass through it. The drilling fluid acts on the rotors, which causes a turbine shaft to rotate and thereby rotate and drive a drill bit connected to the distal end of the turbine shaft. The resulting rotational speed of the drill bit is dependent on the torque from the drill bit and the flow rate of the drilling fluid through the turbine.
Operation of a turbodrill requires the knowledge and expertise of a skilled operator to determine, from the limited surface parameters available, what is happening downhole at the drill bit. While turbodrills are quite efficient and able to drill straight wellbores, in order to be effective, the turbine must be operated within a narrow range of rotational speeds for optimum power output. When the turbine strays from a preferred range of rotational speeds, the efficiency of a turbodrill can rapidly decline.
The available and measurable surface parameters are often not direct indicators of turbine rotation and indeed are sometimes masked by fluctuations in pressure, torque, and weight on bit, all of which can occur because of the various interactions in the wellbore. Accurate indication of rotational speed provides a driller or well operator with important feedback on what is happening at the drill bit, such as knowing how fast the drill bit is rotating, which can lead to improved drilling optimization. Accurate indication of rotational speed also reduces lost rig time in deciding if the drill bit is actually on bottom or whether it is over speeding. Knowing the real-time rotational speed of the drill bit also informs the driller or well operator when the drill bit is sticking on the formation, which could result in extremely high costs to a well operator if a fishing operation is required to retrieve a stuck drill bit. An ability to recognize that the drill bit has stopped will help the driller take appropriate actions to avoid these situations and thereby result in significant savings.
Conventionally, drill bit rotational speed in turbodrills has been monitored at surface locations by measuring the frequency or magnitude of pressure pulses propagated through the entire wellbore from the turbine. In deeper and more complex wells, however, surface detection is extremely limited because of signal attenuation and surface pump noise, each of which serves to complicate and limit the capabilities of using pressure waves to detect downhole rotational speed. In such applications, there is often uncertainty about weight transfer to the drill bit or whether the drill bit is actually biting or otherwise running away on bottom. This uncertainty leads to lost time and hence reduced gross rate of penetration.